Investor pack

Orbost gas plant For

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The information in this presentation:

• Is not an offer or recommendation to purchase or subscribe for shares in Cooper Energy Limited or to retain or sell any shares that are

currently held.

• Does not take into account the individual investment objectives or the financial situation of investors.

• Was prepared with due care and attention and is current at the date of the presentation.

Actual results may materially vary from any forecasts (where applicable) in this presentation.

Before making or varying any investment in shares of Cooper Energy Limited, all investors should consider the appropriateness of that

investment in light of their individual investment objectives and financial situation and should seek their own independent professional advice.

Qualified petroleum reserves and resources evaluator

This report contains information on petroleum resources which is based on and fairly represents information and supporting documentation

reviewed by Mr Andrew Thomas who is a full time employee of Cooper Energy Limited holding the position of Exploration Manager, holds a

Bachelor of Science (Hons), is a member of the American Association of Petroleum Geologists and the Society of Petroleum Engineers and is

qualified in accordance with ASX listing rule 5.41 and has consented to the inclusion of this information in the form and context in which it

appears.

Rounding

All numbers in this presentation have been rounded. As a result, some total figures may differ insignificantly from totals obtained from arithmetic

addition of the rounded numbers presented.

Reserves and resources calculation

Information on the company’s reserves and resources and their calculation are provided in the appendices to this presentation. For

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bbls barrels of oil

boe barrel of oil equivalent

bopd barrel of oil per day

EBITDA earnings before interest, tax, depreciation and amortisation

kbbls thousand barrels

LTIFR Lost Time Injury Frequency Rate. Lost Time Incidents per million man hours worked

MMbbl million barrels of oil

MMboe

NPAT

million barrels of oil equivalent

net profit after tax

PEL 92 SA Cooper Basin acreage held by the PEL 92 joint venture now encompassed by Petroleum Retention

Licences 85 – 104 (refer slide 26)

TSR total shareholder return

1P reserves Proved reserves

2P reserves Proved and Probable reserves

3P Proved, Probable and Possible reserves

1C, 2C, 3C high, medium and low estimates of contingent resources

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Gas resources:

• positioned to commence supply to eastern Australia from late 2018/ early 2019

Oil production:

• 500 kbbls+ pa from Cooper Basin and Indonesia with direct cash costs of A$36 bbl

Strong balance sheet:

• $53 million1 of cash and financial assets, supplemented by finance facilities

Proven management and board team

• proven success in exploration, gas commercialisation and growing resource companies

1 As at 31 December 2014

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Oil & Gas

Australia and Indonesia

People • Extensive knowledge

• Delivery record

• Remuneration & results linked

Funding • Strong balance sheet

• Robust cash flow

• Finance facilities

Assets • Cooper Basin

• Gippsland Basin

• Otway Basin

• South Sumatra, Indonesia

Strategy

Total

Shareholder Return

and

Health Safety Environment Community

• Fundamentals focus: market, technical, cost & commercial

• Leverage and grow strengths

• High margin oil

• Gas portfolio

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Production ~500,000 bbls pa

Total Operating Cost1:

Cooper Basin A$35/bbl, Indo A$50 bbl

Cooper Basin 87%, Indonesia 13%

Focussing on low cost - low risk production

and reserves additions

Gippsland Basin gas & liquids resources

Sole gas field2 in pre-FEED

BMG business case development

Working with buyers on gas contracts

Production uplift of 2 MMboe + from FY19

Prospective Otway Basin onshore acreage

2 Subject to completion

1 Assumes 500,000 bbls and forecast FY15 costs

Callawonga Orbost gas plant

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• Consistent with forecast

• Anticipate stronger Second Half from Indonesia & Cooper

Basin activity

203

271

215

10

29

31

2012 2013 2014

Indonesia

Cooper Basin

Half year production by region

‘000 bbl six months to 31 December

• Cooper Basin: Rincon commissioned, less drilling

in FY14 and FY15 First Half

• Indonesia: well work-over benefits,

development/appraisal drilling underway

• Drilling activity to increase in Second Half

– Cooper Basin: 3 - 6 wells

– Indonesia : 2 - 3 wells

217 225 213

301

246

2010 2011 2012 2013 2014

Half year production '000 bbl six months to 31 December

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• Oil production and exploration

- FY 15 First Half production 1,168 bopd (COE share) from PEL

92 & 93

- FY 15 First Half total operating cost of $36/bbl including

transport and royalties

• Exploration and development continues to add reserves

- in-field development in PEL 92

- new opportunities eg Patchawarra oil in PEL 93

• Revised capex plans has drilling limited to development or low risk appraisal

• Second Half activity to include:

− 3 – 6 development appraisal wells from March

− completion of long term production test of Patchawarra oil pool

at Worrior, PEL 93 For

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• FY 15 First Half production of 169 bopd ( COE share) from Sukananti KSO, South Sumatra

• FY 15 First Half total operating cost of A$54/bbl including transport

• Production rising through workover and development program:

– Tangai-3 workover increased production and 2 new horizons

successfully tested

• Bunian-3, now drilling and expected to test in March 15

• FY 15 Second Half:

– Tangai-4 and Bunian-41 appraisal/development wells

– production expected to increase

• Farming out equity in the Sumbagsel and Merangin III PSC exploration permits

1 Bunian-4 contingent on the results from Bunian-3

Sukananti KSO (COE interest 55%)

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0

100

200

300

400

500

600

700

800

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

PJ

Surat-Bowen

Bass

Otway

Gippsland

Cooper

New supply

contract opportunity

Forecast east coast domestic demand Contracted

supply from:

Source: EnergyQuest

• Strong gas buyer interest

– seeking supply from 2016 onwards

• Discussions with buyers accelerating

• Prices $6 – 9/GJ, based on industry feedback and analysts

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Gippsland Basin

Market

• Market-driven approach

• Building customer relationships

• Terms being negotiated

• Pipeline transport expertise

• Eastern Australia’s largest gas supply source

• Conventional gas, close to market & pipelines

• Supply assets and options:

– Sole gas field and Orbost Gas Plant*

– BMG gas and liquids project

– 19.7% of Bass Strait Oil Company

Otway Basin

• Ideally located: close to markets and pipelines

• Conventional and shale gas opportunities

• Hold extensive position across Penola Trough

* Subject to completion

• Strategy initiated in 2012:

– build gas supply portfolio using

in-house capabilities

• Developed knowledge, portfolio

and gas customer relationships

• Now in project development &

customer negotiations

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Sole gas field & Orbost gas plant

• Acquired 50% of VIC /RL3 incl. Sole gas field1

• Acquired 50% of Orbost gas plant1

• Expect completion April 2015

BMG gas and liquids field

• 65% interest and Operator

• Added 2C Contingent Resources of 18 million boe (COE share)2; including

78 PJ gas and 4.7 MMbbl liquid

• Business Case within June 2015

Gas customers

• Discussions escalated post Sole-Orbost announcement

• Targeting Letters of Intent (LOI) in CY15

Bass Strait Oil Limited

• Shareholding of 19.7%

• Board restructuring

Otway

• Completed analysis of Penola Trough drill results

- confirmed conventional and unconventional gas opportunities

1 Subject to completion conditions (registration and approval of FEED budget) 2 Information on the calculation of resources is included in the appendices to this document

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2015 2016 2017

M J S D M J S D M J S D

FID

Transaction Complete

Contingent Resource added

FID

2P Reserves-Sole

Sign Sole Gas LOIs

Sign BMG Gas LOIs

2P Reserves BMG

Sign Sole gas contracts

Sign BMG gas contracts

Sole

Project development Pre-FEED FEED Construct for late 2018/ Early 2019 start-up

BMG

Project development Business case Pre-FEED

Marketing

Appraisal drilling

FEED

Drill Manta-3

Confirm BMG resource range

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2015 2016

M J S D M J S D

FID 2P Reserves-Sole

Sign Sole Gas LOIs

Project milestones

Funding

Marketing

milestones

Fully funded through to FID

Analyse & identify optimum funding Funding implemented

Sign Sole gas contracts

Funding options to be analysed include:

Sell down equity to realise accumulation in project value (eg reduce from 50% to 40%)

Project financing against 2P reserves and binding long term gas contracts with bankable gas buyers

Participation/funding from gas customers

Sale and lease back of Orbost gas plant

Indicative Value Uplift NPV value increment

~2.5x ~1.5x

Contingent

Resource/

FEED

FID/

Reserves

Pre-start

up

~3.75x

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• Extensive acreage position across Penola Trough

• Jolly-1 and Bungaloo-1 deep wells drilled FY14

– confirmed location of Casterton Formation unconventional play

– identified deep conventional gas play

– shale gas potential reinforced

• Analysis of core and other data has confirmed

opportunity for deep conventional gas reservoir

• Further exploration plans being developed

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• Revenue of $23.0 million, down 38% on lower oil prices and volumes

• Significant non-operating items of $(58.9) million, mainly impairments to Tunisia due to market conditions

• Statutory net loss after tax $(58.0) million vs H1 14 profit of $13.6 million

• Underlying net profit after tax of $0.9 million, down from $ 13.6 million

• Cash and investments of $53.1 million down from $75.1 million at 30 June 2014

• Safety: LTIFR 1of 1.48 vs 0.8 at pcp, single LTI from fractured leg sustained on Indonesia well site

• Production of 0.25 MMbbl, down from 0.30 MMbbl, consistent with forecast

• BMG assets resource registration transfer secured. Business case preparation well advanced.

• Acquisition of 50% of Sole gas field and Orbost gas plant, subject to completion

• Re-affirmed production guidance of 500 kbbls – 560 kbbls

• Production to increase in Second Half subject to appraisal and development drilling results

• FY15 capex guidance cut 35% to $26 million, whilst preserving key priorities, increased weighting to oil production wells and gas milestones

• Completion of Sole-Orbost transaction, addition of Contingent Resources

• Tunisia: divestment ongoing, drilling deferred

1 Lost Time Injury Frequency Rate: lost time incidents per million hours worked (rolling 12 month)

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H1 15 $ million

Oil

Sales revenue 23.0

Gross profit 9.6

Exploration expense 1.2

Admin and other 2.5

Underlying EBITDA 10.1

Underlying EBITDA/Sales Revenue 44.0%

Underlying PBT 5.7

Income tax (1.7)

Oil Underlying NPAT 4.0

Gas and Corporate Underlying NPAT & consolidation (3.1)

Cooper Energy total Underlying NPAT 0.9 For

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Location License Operator March Qtr June Qtr

Cooper

PEL 92 Beach 2-3 development wells and 2

exploration wells

PEL 90, 100,110 Senex 3D seismic processing ongoing

PPL 207 Senex 1 Worrior development/appraisal well

Otway PEL 495 /4 94,

PRL 32 Beach Jolly-1 and Bungaloo-1 studies

ongoing, permit renewals in March

Gippsland

VIC/L26/L27/L28 Cooper Energy Business case within June 2015

VIC/RL3 Santos Sole FEED process starts April

Indonesia

Sukananti KSO Cooper Energy Bunian-3 ongoing. Tangai-5 to follow,

then Bunian-4 (contingent on B-3).

Sumbagsel PSC Cooper Energy Farmout discussions

Merangin III PSC Cooper Energy Farmout discussions

G & G Studies

Development options evaluation

Repro.

AVO/Inversion

Farmout ongoing

FEED

Farmout ongoing

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• Cash generation from existing production

• Sole gas then BMG:

– step changes in production from Dec Qtr

18 and Dec Qtr 19

• Development to be underpinned by bankable

gas sales contracts from FY 16

• Long term foundation being built

* Existing production and appraisal and development

** Current equity share of 50% (Sole) and 65% (BMG), equity selldown to 40% is a funding option

which will be considered

FY 15 FY 16 FY 17 FY 18 FY 19 FY 20 FY 21 FY 22 FY 23 FY 24

Existing Production*: Cooper Basin, Indonesia

Sole

BMG

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Near term:

• Production of 500 – 560 kbbls in FY15; A$/36 bbl cash cost is robust at current prices

• Milestones and catalysts: Sole-Orbost completion and contingent resources, BMG business case and drilling results in SA Cooper

Basin and Indonesia

• Discussions with gas buyers accelerating, letters of intent in CY15

• Fully funded for current activities

• FY15 Capex guidance reduced 35%, with focus on production, reserves and delivery of gas milestones

Beyond FY15:

Moving from 0.5 MMbbl pa oil producer to ~2.5 MMboe oil and gas producer in 3 – 4 years:

• Implementing gas strategy: taking Sole and BMG through development, securing customers and adding value

• Value realisation in Indonesia

• Sole fully funded up to gas project commitment

1 Assumes 500,000 bbls and forecast FY15 costs 2 Subject to completion

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Appendices For

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Key figures

Share price range, 12 months to 28 February 2015 $0.22 - $0.575

Shares on issue 329.2 mill

Market capitalisation ~ $75 mill

Cash & investments1 $53.1 mill

Debt Nil

FY15 production MMbbl/year 0.50 – 0.56

Share register Top 20 holders~66%

Funds/Corp ~67%

131 December 2014

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• Guidance for production of 0.50-0.56 MMbbl

– subject to timing and success of drilling, and timing of new production

commencement

• First Half production of 0.25 MMbbl

• Stronger Second Half production forecast due to uplift from

Indonesian & Cooper Basin development and appraisal drilling

0.41

0.52 0.49

0.59

0.50 to

0.56

0.30

FY11 FY12 FY13 FY14 FY15G

0.25

Outlook Exploration Development

FY15 H2 15 FY 15 H2 15 FY 15 H2 15

Australia

Cooper 7 3 2 1 5 2

Otway 1 - 1 - - -

Gippsland 8 7 3 2 5 5

Indonesia 8 4 2 - 5 4

Tunisia 2 1 2 1 - -

Total 26 16 11 5 15 11

• Opex per barrel A$35/bbl Cooper Basin; A$50/bbl Indonesia

• General admin costs guidance cut to $14.9 million (20% growth on

FY14 of $12.4 million) previously 20% - 25% growth

1 Details provided in Appendices

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• Agreement to acquire 50% of VIC RL/3 and Orbost gas plant

• Sole gas field to FEED on completion for development to supply gas from late 2018/early 2019

• Anticipate addition of approximately 100 PJ Contingent Resources (2C) on completion (200 PJ+ in gross terms)

• Acquisition cost $27.5 million:

− COE to pay $2.5 million on completion

− COE funds first $50 million project costs

• FEED:

− expected to cost $25 million to $29 million

− expected to complete/proceed to FID in Q3, CY16

• Sole Gas Project Development:

− single vertical sub-sea well

− dedicated pipelines and umbilicals to Orbost

− beneficial for BMG development

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• Acquiring 50% of Orbost (Patricia-Baleen) gas plant

• Connected to Eastern Australian gas pipeline

• Currently contracted to process gas from Longtom to

end 2018 (COE not participating in current Longtom

processing)

• Capacity of approximately 90 TJ/day

• Plant modifications for processing Sole gas include

mercury and H2S removal and additional compression

• Strategic location and expansion capacity for

processing of additional 3rd party gas

• Replacement cost estimated $200 - $250 million

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• Acquired 65% interest and operatorship at low cost

– $1 million initial payment and

– $5 million conditional on hydrocarbon production

• Sub-sea infrastructure in place from previous life as oil project with gas injection

• Pre-acquisition review indicates commercial gas development probable at forecast gas prices

• Sole development enhances BMG commerciality

• Reprocessed 3D seismic across existing acreage and areas of interest to assess value add opportunities

• Business Case for development being prepared, due for completion May 2015

• Gas customer discussions advancing

Basker & Manta

Contingent Resource1

(100% JV)

1C (P90) 2C (P50) 3C (P10)

Gas Bcf1 63 104 181

Liquids MMbbls 4 7 11

Total MMboe 17 28 47

1 This table should be read in conjunction with the notes on the assessment and calculation of reserves and

resource provided in the appendices of this document

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Guidance Exploration Development

FY15

original

FY15

revised

FY15

original

FY15

revised

FY15

original

FY15

revised

Australia

Cooper 17 7 7 2 10 5

Otway 1 1 1 1 - -

Gippsland 6 8 6 3 - 5

Indonesia 13 8 7 2 6 5

Tunisia 3 2 3 2 - -

Total 40 26 24 11 16 15

Note: approximate, due to rounding, addition of rounded numbers may not equal totals shown

16 15

24

11

Original Revised

FY15 Capex guidance by type $ million

Exploration

Development

7 9

33

17

Original Revised

FY15 Capex guidance: oil v gas $ million

Oil

GasFor

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• 1,169 km2 in northern SA Cooper Basin

• Lightly explored region subjected to extensive Dundinna

3D seismic survey 577 km2

• Key plays are Hutton/Birkhead and Triassic structural

traps

• Future exploration being evaluated using results of 2

wells drilled in H1 2015:

- Akela-1 cased and suspended

- Jenners-1 plugged and abandoned

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• Expanded acreage coverage of Penola Trough

– traded 35% PEL 495 for 30% PEL 494 & PRL 32

– zero net cost to Cooper Energy

• Jolly-1 and Bungaloo-1 deep wells

– confirmed location of Casterton Formation unconventional play

– identified deep conventional gas play

– shale gas potential reinforced

• Core and other data being analysed

– prior to deciding future activity plans

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Sukananti KSO (COE 55%)

• Currently ~370 bopd (100% basis)

• Multiple low risk development opportunities

• 2-3 development wells planned for 2015

• Targeting production growth

• Contractor share: oil 15%: gas 20%1

Sumbagsel PSC (COE 100%)

• Shallow oil targets

• Farming out for capital efficient drilling

• Contractor share: oil 25%: gas 40%1

Merangin III PSC (COE 100%)

• Highly prospective & large prospects

• Reprocessing seismic to infill 2015 seismic program

• Farming out for capital efficient drilling

• Contractor share: oil 30%: gas 35%1

1 After tax

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• 3 permits covering 12,600 km2

• Hammamet West oil discovery

- gross contingent resource estimated to be

12.6 MMboe (1C) to 110.4 MMboe (3C)1

- oil development opportunity

• Multiple prospects

Divestment plan

• Portfolio to be divested as peripheral to focus on Australia and Indonesia oil and Australia gas

• Divestment process ongoing, interest from prospective buyers tempered by oil price downturn

• Working to satisfactory divestment as soon as practicable

1 Contingent Resource assessments should be read in conjunction with the notes on the assessment and calculation of

reserves and resource provided in the Appendices of this document

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2.16

0 0

2.01

0.59 0.45

30-Jun-13 Production Revisions 30-Jun-14

Proved & Probable (2P) reserves MMbbl

Reserves

MMbbl at 30 June 2014 1P 2P 3P

Cooper Basin 0.71 1.54 2.61

Indonesia 0.14 0.47 0.81

Total 0.85 2.01 3.42

18.0

5.7

17.0

30-Jun-13 30-Jun-14

Contingent Resources (2C) MMboe

Tunisia

Gippsland Basin

Cooper Basin

Contingent Resources2

MMboe at 30 June 2014 1C 2C 3C

Cooper Basin 0.00 0.01 0.03

Gippsland Basin 10.8 18.0 30.6

Tunisia 8.9 17.0 39.5

Total 19.8 35.1 70.1

2 Conventional resources only

1 This information on reserves and resources should be read in conjunction with the information provided on the calculation of Reserves and Resources on page 26

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Reserves include Cooper Energy’s share of future crude fuel usage in the Cooper Basin. The estimated fuel usage is; 1P 0.02 MMbbl, 2P 0.05 MMbbl and 3P 0.08 MMbbl. There is no produced crude oil used for fuel in Indonesia.

Categories are aggregated by arithmetic summation. Basin and Company totals are aggregated by arithmetic summation. Aggregated 1P may be a very conservative estimate and aggregated 3P may be a very optimistic estimate due to the effects of arithmetic summation of probabilistic estimates.

The Contingent Resource assessment includes resources in Basker and Manta fields, in the Gippsland Basin, as released to the ASX on 18 August 2014 and the Hammamet West field in the Bargou Permit, offshore Tunisia, as released to the ASX on 28 April 2014. Cooper Energy is not aware of any new information or data that materially affects the information provided in those releases, and all material assumptions and technical parameters underpinning the estimates provided in the releases continue to apply and have not changed .

Contingent Resources in the Basker and Manta fields have been assessed using deterministic simulation modelling for the Intra-Latrobe Group and probabilistic estimation for the Manta Field Golden Beach Subgroup. This methodology incorporates a range of uncertainty relating to each of the key reservoir input parameters to predict the likely range of outcomes. This approach is consistent with the definitions and guidelines in the Society of Petroleum Engineers (SPE) 2007 Petroleum Resources Management System (PRMS). Contingent Resources for the Basker and Manta Fields have been aggregated by arithmetic summation. Conversion factors for the Basker and Manta fields are 1 Bcf = 1.153 PJ and 1 boe = 5,051 scf (1 Bcf = 0.198 MMboe).

Contingent Resources in Hammamet West have been assessed using probabilistic Monte Carlo statistical methods. This methodology incorporates a range of uncertainty relating to each of the key reservoir input parameters to predict the likely range of outcomes. This approach is consistent with the definitions and guidelines in the Society of Petroleum Engineers (SPE) 2007 Petroleum Resources Management System (PRMS).

Totals may not reflect arithmetic addition due to rounding. Categories are aggregated by arithmetic summation. Field, Basin and Company totals are aggregated by arithmetic summation. Aggregated 1C may be a very conservative estimate and aggregated 3C may be a very optimistic estimate due to the effects of arithmetic summation of probabilistic estimates.

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Website: cooperenergy.com.au

Investor relations: Don Murchland +61 439 300932

donm@cooperenergy.com.au

Address: Cooper Energy Limited Level 10 Waymouth St

Adelaide SA 5000

+ 61 8 8100 4900

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